Migration Effects on Crude Oil Composition in West and East Cameron, Offshore Louisiana
This work was first published 23 years ago in a conference proceedings (from Latin Amer. Congress on Org. Geochemistry, Cancun Mexico, 253‐255, 1996). The following is the abstract from the proceedings. In the authors’ opinions, this work demonstrates practical methodology using geochemistry and exploration impact of understanding the mechanistic reason for a gas condensate; evaporative condensate, production condensate, or thermal condensate. Gas induced phase segregation of oil columns has proven to be a major pathway to hydrocarbon emplacement and alteration. The conventional paradigm at the time for shelf Gulf of Mexico was that drilling deeper would not yield black oil, only drier gas. Early oil to gas cracking kinetics also feed this paradigm. Recognizing fractionation condensates from vertical migration opened the concept to drill deeper for black oil and reopened previous mature areas for exploration. Abstract‐A detailed geochemical study was initiated to determine the causes of variability in produced hydrocarbons in a relatively small geographic area in West and East Cameron, offshore Louisiana. Bulk chemical differences in produced condensates and oils from the East Cameron 64, 62, 49, and 46 and West Cameron 192 and 222 fields were found to be attributed primarily to phase separation during secondary migration and to current reservoir pressure and temperature conditions and biodegradation in shallow reservoirs. There is no evidence for multiple source rocks in the studied area. The source rock was not identified, but geochemical evidence indicates the oils are sourced from a rock with mixed type II/III kerogen. It is proposed that overpressured reservoirs produce greater volumes of oil (and with a lower API gravity) relative to produced volume of gas because higher molecular weight hydrocarbons are better solubilized in methane under the overpressure conditions. Based on oil cracking kinetics and present‐day reservoir temperatures, if Oligocene or Lower Miocene source rocks generated the oils found in the study area, then oil accumulations might be expected at depths up to 18,000 ft. If the Cretaceous source rocks generated the oils, then current drilling depths are already near the maximum depth (14,500 to 16,500 ft.) at which oil is likely to be found. The study indicates that oil may be present in traps stratigraphically below the main field production. Integration of fluids composition data with geologic data may be useful in determining the timing of fault movement with respect to hydrocarbon charge for a given reservoir. Local field size geochemical studies can be valuable in development drilling in mature exploration areas.
AAPG Datapages/Search and Discovery Article #90349 © 2019 AAPG Hedberg Conference, The Evolution of Petroleum Systems Analysis: Changing of the Guard from Late Mature Experts to Peak Generating Staff, Houston, Texas, March 4-6, 2019